The heating value of natural gas has a significant impact on its monetary value. In general, the heating value of natural gas increases as the concentration of low volatility, high molecular weight components increases. Condensation of gas phase components, which reduce the proportion of high molecular weight components, therefore tends to decrease gas phase heating value while vaporization of entrained liquid has the opposite effect.
In order for natural gas supply to balance with demand over the next 10 to 20 years it will be necessary to increase production from deep-water fields in the Gulf of Mexico. (Refer to Volume 1, Fall/Winter 1997 official newsletter of Colorado Engineering Experiment Station Inc.) Gas produced from deep-water fields, containing higher concentrations of low volatility components such as water vapor and heavy hydrocarbons, has a higher susceptibility to condensation than shelf and onshore production gas. Additionally, some onshore produced gas, particularly in low ambient temperature regions, frequently contain entrained liquids. Other liquids which can influence vapor phase composition when fluid pressure or temperature changes occur are glycols and amines which are carried over into the gas phase from gas contactors designed to remove water vapor and acid gases respectively.
A Joint Industry Project (JIP) is underway to address problems associated with measurement and transportation of “wet gases”. A part of the JIP focus will include improvement of wet gas sampling techniques.
The American Petroleum Institute (API) and the Gas Processors Association (GPA) are two leading industry organizations having recommended standard practices for sampling and analysis of natural gas. Both recommend that entrained liquids are to be removed from natural gas samples at prevailing source gas pressure and temperature. (Refer to Manual of Petroleum Measurement Standards chapter 14—Natural Gas fluids measurement, section 1 collecting and handling natural gas samples for custody transfer, fourth edition, August 1993.) This is done to prevent gas phase compositional changes caused by vaporization and condensation.
Following the recommended practices has been almost impossible due to lack of available hardware to accomplish the task. For example GPA recommends a separator design (FIG. 6 in the aforementioned API document) which at best is suited for removal of liquid slugs and large droplets, neither, of which cause frequent sampling problems. Furthermore, there is no provision for maintaining process source gas temperature. Liquid aerosol, which are the most frequent source of liquid entrainment, are not easily separated from sample gas by this “Knock-Out” type of GPA separator.
Conventional mechanical coalescer elements constructed of fibers, screens, etc. require gas flow thru the element for aerosol coalescing to occur. In most cases this precludes the return of the coalesced liquid to the process gas source at the original source pressure. With increasing environmental concerns disposal of the coalesced liquid can present serious problems if it cannot be returned to the original source.
Gas phase separation membranes are known and utilized in stack and flue gas analyzers for removal of entrained water, sub-micron aerosols, and filtration of ultra-fine particulates; examples of such membranes include the gas phase separation membranes utilized in the GENIE Series 100 line from A+ Corporation of Prairieville, La. USA. However, the utilization of said membranes is not believed contemplated in conjunction with the system of the present invention.